Distance Setting Excel

PTD-HA/3000467425/ED2.121.001.W-0 Document no.- Rev - 2

SIEMENS

RELAY SETTING CALCULATION 220 KV DURSHED FEEDER - 2 DISTANCE PROTECTION RELAY

NEW 400/220KV SUBSTATION AT WARANGAL TRANSMISSION SYSTEM ASSOCIATED WITH GRID STRENGTHENING FOR TAMILNADU & ANDRA PRADESH LOA REF: C-55807-S119A-7/LOA-1/2020 DATED 31.03.2006 POWERGRID CORPORATION OF INDIA LIMITED

Name

Department

Telephone

Place

Date

LAXMINARAYAN

PTD-HA

0124-2846155

GURGAON

-

Signature

Author: Approval:

Rev

Date

Revised items

1

04.10.08

FOR APPROVAL

2

19.12.08

SETTING REVISED

Page no

ALL

Remarks

Name of

Name of

reviser

Approver

KNR

RL

KNR

RL

Total pages

Siemens Ltd., PTD Division Copying this document, and giving it to others and the use or communication of the contents thereof, are forbidden without express authority. Offenders are liable to the payment of damages. All rights are reserved in the event of the grant of patent or registration of a utility model or design

25

400/220 KV WARANGAL SUBSTATION 220kV DURSHED FEEDER SIEMENS DISTANCE PROTECTION RELAY SETTING CALCULATION 1.0 Relay Data: 1.01 ANSI No.

=

21

1.02 Description

= Distance + Over Voltage Prot.

1.03 Make

= SIEMENS

1.04 Model No.

= 7SA522

2.0 Input Data: 2.01 System voltage

=

220

KV

2.02 Source substation

= WARANGAL

2.03 Conductor used

= ACSR Kundah

2.04 Protected Line length

=

71

(R1=R2)

=

0.0791

Ω/KM

(X1=X2)

=

0.403

Ω/KM

R0

=

0.255

Ω/KM

X0

=

1.51

Ω/KM

2.07 Longest Line length

=

50

2.08 Conductor used

= ACSR KUNDAH

400/220KV

Km

2.05 Positive & Negative Sequence Line Impedance /KM

2.06 Zero Sequence Line impedance per KM

Km

2.09 Positive & Negative Sequence Line Impedance /KM (R1=R2)

=

0.079

Ω/KM

(X1=X2)

=

0.403

Ω/KM

R0

=

0.255

Ω/KM

X0

=

1.51

Ω/KM

2.11 Shortest Line length (Durichedu 1 Fdr.)

=

71

2.12 Conductor used

= ACSR KUNDAH


1 of 25

Km

2.13 Positive & Negative Sequence Line Impedance /KM (R1=R2)

=

0.079

Ω/KM

(X1=X2)

=

0.403

Ω/KM

R0

=

0.255

Ω/KM

X0

=

1.51

Ω/KM

Magnitude

Angle


2.15 3Ф fault current at WARANGAL 220 KV Substation = 2.16 1Ф fault current at WARANGAL 220 KV Substation

40000

-79

Magnitude

Angle

=

40000

-79

2.17 Tower Footing Resistance

=

10

2.18 Direction - Zone I

= Forward

2.19 Direction - Zone II

= Forward

2.20 Direction - Zone III

= Forward

2.21 Direction - Zone IV

= Reverse

2.22 Direction - Zone V

= Disabled

2.23 Direction - Zone 1B

= Forward

2.24 Time delay - Zone I

=

0

sec

2.25 Time delay - Zone II

=

0.4

sec

2.26 Time delay - Zone III

=

1

sec

2.27 Time delay - Zone IV

=

1

sec

2.28 Time delay - Zone V

=

∞

sec

2.29 Time delay - Zone 1B

=

0

sec

Ω

3.0 Err:511 3.01 C.T Ratio

= 1600-800/1A

3.02 Selected Ratio

=

800

3.03 Class

=

PS

3.04 KPV

=

800

2 of 25

/

1

V

3.05 Iex

=

<=50

3.06 Rct

=

4

ma Ω

4.0 Err:511 4.01 P.T Ratio

=(

220 KV / √ 3 ) / ( 0.11KV / √ 3 )

4.02 Class

=

3P

4.03 Burden

=

50

VA

5.0 Transformer Data at Next 220KV Substation 5.01 Voltage level & Type

= 220KV / 132KV Auto transformer

5.02 220KV / 132KV Auto transformer

=

2

Nos.

5.03 Rating of Transformer

=

100

MVA

5.04 Vector Group

=

YNa0d11

a) Z1 at Principal Tap

=

12.50%

b) Z0 at Principal Tap

=

11.50%

5.06 High Voltage

=

220

KV

5.07 Medium Voltage

=

132

KV

5.08 Low Voltage

=

11

KV

5.05 Percent Impedances HV-MV ± 10%

6.0 MAIN I DISTANCE PROTECTION: 6.1 Protected Line parameters: 6.1.1 Conductor used

= ACSR Kundah

6.1.2 Line Length

=

71

KM

(R1=R2)

=

0.0791

Ω/KM

(X1=X2)

=

0.403

Ω/KM

6.1.3 Positive & Negative Sequence Line Impedance /KM

6.1.4 Positive Sequence impedance of the Line

Magnitude

Per unit length(Z1) in Ω/KM

= √(R12 + X12) 3 of 25

Angle tan-1(X1/R1)

=

0.41069

78.9

= Err:511

6.1.5 Zero Sequence Line impedance per KM R0

=

0.255

Ω/KM

X0

=

1.51

Ω/KM

6.1.6 Zero Sequence impedance of the Line

Magnitude

Per Unit Length (Z0) in Ω/KM

= √(R02 + X02) =

1.53138

Angle tan-1(X0/R0) 80.41

= Err:511

6.2 Longest Line parameters at Next 220KV Substation 6.2.1 Conductor used 6.2.2 Line Length

= ACSR KUNDAH Assumed

=

50

KM

(R1=R2)

=

0.079

Ω/KM

(X1=X2)

=

0.403

Ω/KM



Magnitude


= √(R12 + X12) =

0.41067


= Err:511 6.2.5 Zero Sequence Line impedance per KM R0

=

0.255

Ω/KM

X0

=

1.51

Ω/KM


Magnitude


= √(R02 + X02) =

1.53138

= Err:511

6.3 Shortest Line parameters at Next 220KV Substation 4 of 25


6.3.1 Conductor used 6.3.2 Line Length

= ACSR KUNDAH Assumed

=

71

KM

(R1=R2)

=

0.079

Ω/KM

(X1=X2)

=

0.403

Ω/KM



Magnitude


Angle

= √(R12 + X12) =

tan-1(X1/R1)

0.41067

78.9

= Err:511 6.3.5 Zero Sequence Line impedance per KM R0

=

0.255

Ω/KM

X0

=

1.51

Ω/KM


Magnitude


Angle

= √(R02 + X02) =

tan-1(X0/R0)

1.53138

80.4

= Err:511

6.4 Transformer Rating at Next 220kV Substation 6.4.1 220KV / 132KV Auto transformer

=

2

Nos

6.4.2 Rating of Transformer

=

100

MVA

6.4.3 Vector Group

=

YNa0d11

Z1 at Principal Tap

=

12.50%

Z0 at Principal Tap

=

11.50%

6.4.4 Percent Impedances HV-MV

6.4.5 Magnetising Inrush Current

± 10%

= 6 times of the rated current = 6 x 262.44 =

6.4.6 Line Current(HV)

1574.64

= Rating/(√3 x V) 5 of 25

A

= 100000 / (1.732 x 220 ) = 6.4.7 Line Current(MV)

262.44

A

= Rating/(√3 x V) = 100000 / (1.732 x 132 ) =

6.4.8 Line Current(LV)

437.4

A

= Rating/(√3 x V) = 100000 / (1.732 x 11 ) =

5248.79

A

6.5 System Parameter: 6.5.1 3-Phase Fault Level: a)

Maxium 3Ф Fault Current as per Calculation at Err:511

Magnitude =

40000

Angle -79

= Err:511 = Therefore, maximum 3 Φ Fault Level

40

KA

= √3 x Isc x V = √3 x 40x 220

b)

15241.6

MVA

=

12000

Amps

=

12

KA

=

X1 / R1

Minimum 3 Φ Fault current (assumed-30% of max)

c)

=

X/R Ratio As per Calculations

= 0.403 / 0.0791 =

5.095

6.5.2 1-Phase Fault Level: a)

Maxium 1Ф Fault Current as per Calculation at 220KV BUS of Warangal SubStation

Magnitude =

40000

Angle -79

= Err:511 = 6 of 25

40

KA

Therefore, maximum 1 Φ Fault Level

= Isc x V = Err:511

b)

8800

MVA

=

12000

Amps

=

12

KA

=

X1 / R1

Minimum 1 Φ Fault current (assumed-30% of max)

c)

=

X/R Ratio As per Calculations

0.403 / 0.0791 5.095

6.6 Conversion of CT & PT Secondary Values: Zsec

=

x Zpri

C.T Ratio P.T Ratio

=

Err:511

x Zpri

( 220/ √3 ) / ( 0.11 / √3 )

=

0.4

X Zpri

6.7 Line Impedances of the Protected Line:

6.7.1 Positive Sequence Impedance of the

= Positive sequence impedance x

Protected Line(Z1)

Protected line length = ( 0.41069 < 78.9°) x 71 Magnitude =

6.7.2 Positive sequence Impedance of the

29.15899

Angle 78.9 ohms

= Positive sequence impedance x C.F

Line per unit Length (X) refered to sec. in Ω/KM = ( 0.41069 < 78.9°) x 0.4 7 of 25

Magnitude =

0.164276

6.7.3 Line Angle

=

78.9

6.7.4 Distance Angle

=

78.9

Angle 78.9 ohms

(Assumed equal to Line Angle)

6.7.5 Zero Sequence Impedance of the

= Zero sequence impedance x

Protected Line(Z0)

Protected line length = Err:511 Magnitude =

108.72798

Angle 80.41 ohms

6.7.6 Zero Sequence Compensation Factor RE/RL =

1/3 * ((R0/R1) - 1)

= 1/3 x (( 0.255 / 0.079 ) -1) =

0.743

6.7.7 Zero Sequence Compensation Factor XE/XL =

1/3 * ((X0/X1) - 1)

= 1/3 x (( 1.51 / 0.403 ) -1) =

0.916

6.7.8 Zero Sequence Compensation Factor Ko =

1/3 * ((Z0/Z1) - 1)

= 1/3 x ((1.53138 / 0.41067) - 1) Magnitude = 0.910

8 of 25

Angle -178

6.8 Apparent Maximum Power: 6.8.1 Apparent Maximum Power:

=

150.00

MVA

=

150.00

MVA

6.8.2 Rated full load current

=

393.66

Amps

6.8.3 Source Impedance

= (2202/Max. 3 ph Fault MVA) Magnitude =

Angle

3.18

78.91

6.9 Maximum Allowable Reach: 6.9.1 Min. Load Impedance at 0.8 p.f

= (KV2 / (MVA)) x CF = ( 220^2 / ( 150 )) x 0.4 ) = 129.07

6.9.2 Maximum reach of Load Impedance

Ω

= 80% of min. Load impedance = 0.8 x 129.07 = 103.256

Ω

7.0 Computation of Fault Resistance Tolerance for Reach Setting : 7.1 Tower Footing Resistance

=

7.2 Arc Resistance (RArc) =

10

Ω

= 76KV2/Short ckt. KVA at min. Fault Current =

1.26

Ω

7.3 For Phase to Phase Fault: Rt-Φ (Considering 50% of Arc Resistance including a safety margin of 20%) Resistance Tolerance with respect to Secondary =

0.312

Ω

7.4 For Phase to Earth Fault :- Resistance Tolerance with respect to secondary-Rt-e = 1.2 x (1+I2/I1*((Rarc+RTF)/(1+RE/RL)) x C.F = 1.2 x (1+ 3 x ((10 + 1.26 ) / (1 + 0.743 )) x 0.4 =

9.783

Ω

Where, I2/I1 is ratio of current at the opposite end and local end =

9 of 25

3

8.0

DISTANCE RELAY PROTETION FOR 220KV Line feeder - 1

8.1 Zone I : Reach Setting Proposed at 80% of the protected Line 8.1.1 Direction

= Forward

8.1.2 Resistive Reach For Φ to Φ Faults,

= (80%x L x R(Z1) x C.F)+(R-TolerenceΦ-Φ)

R(Z1):

= ( 0.8 x 71 x 0.0791 x 0.4 ) + 0.312 = 2.109

8.1.3 Resistive Reach For Φ to E Faults, RE(Z1):

Ω

= (R(Z1) x Ko)+R-TolerencePh-E = ( 0.8 x 71 x 0.0791 x 0.4 ) x 0.91 ) + 9.783 = 11.418

10 of 25

Ω

8.1.4 Reactance Reach,X(Z1)

= 80% ofProtected line * X1 * C.F = 0.8 x 71 x 0.403 x 0.4 = 9.156

8.1.5 Time Delay:

Ω

=0

secs

Selected Setting: Zone

Resistive Reach for Ph to Earth Fault,RE(Z1)

Zone I

11.418

Resistive Reach for Reactance Reach, Direction Ph to Ph X(Z1) Fault,R (Z1) Forward 2.109 9.156

Protected Length

Time Delay

80%

0

8.2 Zone II: Reach Setting Proposed at (100% of the protected Line + 50% of the shortest line at Next substation) 8.2.1 Direction

= Forward

8.2.2 Resistive Reach For Φ to Φ Faults,R(Z2):

= (((100% of Prot. line length x R1) + (50% of short line x R1)) x C.F)+Rt-Φ = ((1 x 71 x 0.0791) + (0.5 x 71 x 0.079) x 0.4)+(0.312) = 3.68

8.2.3 Resistive Reach For Φ to E Faults,RE(Z2):

Ω

= (R(Z2) x Ko) + Rt-e [ { (1 x 71 x 0.0791) + (0.5 x 71 x 0.079) x 0.4 } x = 0.91 ] + 9.783 = 12.848


Ω

= ((100% of Prot. line length x X1) + (50% of short line x X1) x C.F ((1 x 71 x 0.403) + (0.5 x 71 x 0.403) x 0.4 = 17.168

8.2.5 Time Delay:

= 0.4

Selected Setting:

11 of 25

Ω secs

Zone


Direction

Zone II

12.848

Forward

Reactance Resistive Reach Reach, for Ph to Ph X(Z2) Fault,R(Z2) 17.168

3.68

Protected Length

Time Delay

100%

0.4

8.3 Zone III: Reach Setting 8.3.1 Base Impedance of the Transformer

= KV2 / MVA = Err:511 = 484

8.3.2 Equivelent Transformer Impedance

Ω

= (KV2 / MVA)*Zo = (220^2 / 100) x 0.115 = 55.66

8.3.3 Impedance of two transformers running in Parallel

=

8.3.4 Impedance of Protected line at 100%

Ω

28

Ω

= (Protected line x Z1 x C.F) = (71 x 0.41069 x 0.4)

8.3.5 Total Impedance of both Transformers &

=

11.66

=

39.66

Ω

Protected Line At 100% (Comparing the above value with the reach of prot. line and the longest line at the remote) 8.3.6 Zone-3 impedance

= (110% PL+100% OF NEXT) =

52.61 Ω

Largest line at the Remote StationPrimary value As the transformer capacities are variable the reach is as calculted from the above 8.3.8 is taken for reach setting which is nearer to the calculated value at8.3.5

8.3.7 Direction

8.3.8 Resistive Reach For Φ to Φ Faults, R(Z3)

= Forward

= { [(110% of Protected line length x R1) + (100% of longest line x R1) ] x C.F } + Rt-Φ [(1.1 x 71 x 0.0791) + (50 x 0.079) ] x 0.4)+ 0.312 4.362

8.3.9 Resistive Reach For Φ to E Faults,

Ω

= { [(110% of Protected line length x R1) + 12 of 25

RE(Z3)

(100% of longest line x R1) ] x C.F } + Rt-e [(1.1 x 71 x 0.0791) + (50 x 0.079) ] x 0.4)+ 9.783 13.833

8.3.10 Reactance Reach, X(Z3)

Ω

= { 110% of Protected line length x X1) + (100% of longest line x X1) ] x C.F } [(1.1 x 71 x 0.403) + (50 x 0.403) ] x 0.4) 20.65 Ω

8.3.11 Time Delay:

=

1

secs

Selected Setting:

(110% PL+100%

Zone


Direction

Zone III

13.833

Forward


4.362

Protected Length

Time Delay

110%

1

8.4 Zone IV: Reach Setting Proposed at 25% of Zone1 8.4.1 Direction

= Reverse

8.4.2 Resistive Reach For Φ to Φ Faults,R(Z4):

= 0.25 x R(Z1) = 0.25 x 2.109 = 0.527

8.4.3 Resistive Reach For Φ to E Faults,RE(Z4):

Ω

= 0.25 x RE(Z1) = 0.25 x 11.418 = 2.855

Ω

= 0.25 * X(Z1)


= 0.25 x 9.156

8.4.5 Time Delay:

= 2.289

Ω

=

secs

1

Selected Setting: Zone


Direction

Zone IV

2.8545

Reverse

Reactance Resistive Reach Reach, for Ph to Ph X(Z2) Fault,R(Z2)

13 of 25

2.289

0.5273

Protected Length

Time Delay

25%

1

8.5 Zone V Relay Setting

Disabled

8.6 Controlled Zone (Z1B) Reach Setting Proposed at 120% of the Protected Line 8.6.1 Direction

=1

Forward

8.6.2 Resistive Reach For Φ to Φ Faults,R(ZIB) at 120% of the Protected Line

= (120% of Protd linex R1xC.F)+Rt-Ph = 1.2 x 0.0791 x 71 x 0.4) + 0.312 =

3.008

Ω

8.6.3 Resistive Reach For Φ to E Faults,RE(ZIB) at 120% of the Protected Line

= (120% of Protd line x R1 x Ko x C.F) + Rt-E = (1.2 x 71 x 0.0791 x 0.4 x 0.91) + 9.783 =

12.2361

Ω

8.6.4 Reactance Reach, X(ZIB) at 120% of the Protected Line

= 120% of Protected line * X1 * C.F = 1.2 x 0.403 x 71 x 0.4

8.6.5

Time Delay

=

13.734

=

0

Ω secs

Selected Setting:

9

Zone


Direction

Zone IB

12.24

Forward


3.01

OVER VOLTAGE PROTECTION:

9.1

1 Voltage Protection

: Enabled

9.2

2 Over Voltage Phase - Earth Protection:

9.3

Uph-e>(>): Phase Voltage Stages

9.4

Uph-e> :

Initial Stage for Minor Over voltage

110%of Un=

9.5

TUph-e> :

Time Delay for Initial Stage Setting

=

=

14 of 25

ON 69.85 5

Volts Secs

Protected Length

Time Delay

120%

0

9.6

Uph-e>> :

9.7

TUph-e>> : Time delay for Longer Setting

=

9.8

Uph-e>(>) RESET: Drop out to Pick Up Ratio

=

9.9

CURR.SUP.Uph-e>:

= ON

Stage for Higher Voltage

150%ofUn=

95.25 0

Volts Secs

0.95

11.0 DIRECTIONAL EARTH FAULT 11.1

Zero Sequence Source

=

3 x KV2

Impedance (Z0s)

√3 x 220 x Min.1ph Fault Current = 3 x 220^2 / (√3 x 220 x 12)

11.2

Line Impedance of the Protected Line

11.3

Earth Fault Current Pick-up

=

= 31.755196

Ω

Forward

Ω

= 20% of rated Full load current / C.T ratio

Setting(3I0>) = (0.2 x MVA / (√3 x KV)) / C.T ratio = (0.2 x 150000 / (1.732 x 220)) / ( 800 / 1) = 0.0984149

≈

0.1 A

11.4

Earth Fault Current Pick-up setting(3I0>>)

= Disabled

11.5

Direction

= Forward

11.6

Curve

= Normal Inverse

11.7

TMS

= 0.337

11.8

Zero Sequence Voltage Stage 3U0>

= Enabled

11.9

Characteristic Angle

= Enabled

11.10 Tele protection Earth Fault:

= N/A

Directional Comparison Pick-up 13.0 SOTF O/C 12.1 SOTF OVER CURRENT

= Enabled

12.2 The magnitude of the current for picking up of the switchon to fault

I>>>

= 2.5 times the FLC = 2.5 x 150000 / (1.732 x 220) 15 of 25

= 12.3 Setting adopted = 2.5 times FLC/ CTR

I>>>

16 of 25

984

A

1.23

A

400/220 KV WARANGAL SUBSTATION 220kV DURSHED FEEDER SIEMENS DISTANCE PROTECTION RELAY SETTING 1 Device Configuration No.

Function

Scope

103

Setting Group Change Option

Disabled

110

Trip mode

3 pole

112

Phase Distance

Quadrilateral

113

Earth Distance

Quadrilateral

120

Power Swing detection

Enabled

121

Teleprotection for Distance prot.

POTT

122

DTT Direct Transfer Trip

Disabled

124

Instantaneous HighSpeed SOTF Overcurrent

Enabled

125

Weak Infeed (Trip and/or Echo)

Disabled

126

Backup overcurrent

131

Earth fault overcurrent

Time Overcurrent Curve IEC

132

Teleprotection for Earth fault overcurr.

Disabled

133

Auto-Reclose Function

1 AR-cycle

134

Auto-Reclose control mode

with Trip and Action time

135

Synchronism and Voltage Check

Disabled

136

Over / Underfrequency Protection

Disabled

137

Under / Overvoltage Protection

Enabled

138

Fault Locator

Enabled

140

Trip Circuit Supervision

Disabled

Disabled

2 General Device Settings 2.1 Group Device No.

Settings

Value

610

Fault Display on LED / LCD

Display Targets on TRIP only 15 of 25

640

Start image Default Display

image 1

3 Power System Data 1 3.1 Group Power System Data 1; Group Transformers No.

Settings

Value

201

CT Starpoint

towards Line

203

Rated Primary Voltage

220 KV

204

Rated Secondary Voltage (Ph-Ph)

110 V

205

CT Rated Primary Current

800.00 A

206

CT Rated Secondary Current

1A

210

U4 voltage transformer is

Usy2 transformer

211

Matching ratio Phase-VT To Open-Delta-VT

1.73

215

Matching ratio Usy1 / Usy2

1

220

I4 current transformer is

Neutral Current (of the protected line)

221

Matching ratio I4/Iph for CT's

1

3.2 Group Power System Data 1; Group Power System No.

Settings

Value

207

System Starpoint is

Solid Earthed

230

Rated Frequency

50 Hz

235

Phase Sequence

L1 L2 L3

236

Distance measurement unit

km

237

Setting format for zero seq.comp. format

Zero seq. comp. factors RE/RL and XE/XL

0238A

Earth Fault O/C: setting for 1pole AR

all stages together

3.3 Group Power System Data 1; Group Breaker No.

Settings

Value

0240A

Minimum TRIP Command Duration

0.10 sec

0241A

Maximum Close Command Duration

0.10 sec

242

Dead Time for CB test-autoreclosure

1.00 sec

4 Settings groups

16 of 25

4.1 Group Power System Data 2; Group Power System No.

Settings

Value

1103

Measurement: Full Scale Voltage (100%)

220 KV

1104

Measurement: Full Scale Current (100%)

800.00 A

1105

Line Angle

78.9

1211

Angle of inclination, distance charact.

78.9

1107

P,Q operational measured values sign

not reversed

1110

x' - Line Reactance per length unit

0.164276

1111

Line Length

71.0 KM

1116

Zero seq. comp. factor RE/RL for Z1

0.74

1117

Zero seq. comp. factor XE/XL for Z1

0.92

1118

Zero seq. comp.factor RE/RL for Z1B...Z5

0.74

1119

Zero seq. comp.factor XE/XL for Z1B...Z5

0.92

4.2 Group Power System Data 2; Group Line Status No.

Settings

Value

1130A

Pole Open Current Threshold

0.10 A

1131A

Pole Open Voltage Threshold

30 V

1132A

Seal-in Time after ALL closures

0.20 sec

1133A

minimal time for line open before SOTF

0.25 sec

1134

Recognition of Line Closures with

CBaux OR Current or Manual close BI

1135

RESET of Trip Command

with CBaux open AND I < PoleOpenCurrent

1136

open pole detector

with measurement (U/I,trip,pickup,CBaux)

1140A

CT Saturation Threshold

5.0 A

1150A

Seal-in Time after MANUAL closures

0.30 sec

1151

Manual CLOSE COMMAND generation

NO

1152

MANUAL Closure Impulse after CONTROL

4.3 Group Power System Data 2; Group Trip 1-/3-pole No.

Settings

Value

17 of 25

1155

3 pole coupling

with Trip

1156A

Trip type with 2phase faults

3pole

4.4 Group Distance protection, general settings; Group General No.

Settings

Value

1201

Distance protection

ON

1202

Phase Current threshold for dist. Meas.

0.10 A

1211

Angle of inclination, distance charact.

78.9

1208

Series compensated line

NO

1232

Instantaneous trip after SwitchOnToFault

with Zone Z1B

1241

R load, minimum Load Impedance (ph-e)

129.1 Ohms

1242

PHI load, maximum Load Angle (ph-e)

37 °

1243

R load, minimum Load Impedance (ph-ph)

258.1 Ohms

1244

PHI load, maximum Load Angle (ph-ph)

45 °

1317A

Single pole trip for faults in Z2

NO

1357

Z1B enabled before 1st AR (int. or ext.)

YES

4.5 Group Distance protection, general settings; Group Earth faults No.

Settings

Value

1203

3I0 threshold for neutral current pickup

0.10 A

1204

3U0 threshold zero seq. voltage pickup

5V

1207A

3I0>-pickup-stabilisation (3I0> /Iphmax)

0.15

1209A

criterion of earth fault recognition

3I0> OR 3U0>

1221A

Loop selection with 2Ph-E faults

all loops

4.6 Group Distance protection, general settings; Group Time Delays No.

Settings

Value

1210

Condition for zone timer start

with distance pickup

1305

T1-1phase, delay for single phase faults

0.00 sec

1306

T1multi-ph, delay for multi phase faults

0.00 sec

1315


0.40 sec

18 of 25

1316


0.40 sec

1325

T3 delay

1.00 sec

1335

T4 delay

1.00 sec

1345

T5 delay

N/A

1355

T1B-1phase, delay for single ph. Faults

0.00 sec

1356

T1B-multi-ph, delay for multi ph. Faults

0.00 sec

4.7 Group Distance zones (quadrilateral); Group Zone Z1 No.

Settings

Value

1301

Operating mode Z1

Forward

1302

R(Z1), Resistance for ph-ph-faults

2.109 Ohms

1303

X(Z1), Reactance

9.156 Ohms

1304

RE(Z1), Resistance for ph-e faults

11.418 Ohms

1305


0.00 sec

1306


0.00 sec

1307

Zone Reduction Angle (load compensation)

0°

4.8 Group Distance zones (quadrilateral); Group Zone Z1Bexten. No.

Settings

Value

1351

Operating mode Z1B (_verreach zone)

Forward

1352

R(Z1B), Resistance for ph-ph-faults

3.008 Ohms

1353

X(Z1B), Reactance

13.734 Ohms

1354

RE(Z1B), Resistance for ph-e faults

12.236 Ohms

1355

T1B-1phase, delay for single ph. Faults

0.00 sec

1356

T1B-multi-ph, delay for multi ph. Faults

0.00 sec

1357

Z1B enabled before 1st AR (int. or ext.)

YES


Settings

Value

1311

Operating mode Z2

Forward

1312


3.680 Ohms

19 of 25

1313

X(Z2), Reactance

17.168 Ohms

1314


12.848 Ohms

1315


0.40 sec

1316


0.40 sec

1317A

Single pole trip for faults in Z2

NO


Settings

Value

1321

Operating mode Z3

Forward

1322


4.362 Ohms

1323

X(Z3), Reactance

20.650 Ohms

1324


13.833 Ohms

1325

T3 delay

1.00 sec


Settings

Value

1331

Operating mode Z4

Reverse

1332


0.527 Ohms

1333

X(Z4), Reactance

2.289 Ohms

1334


2.855 Ohms

1335

T4 delay

1.00 sec


Settings

Value

1341

Operating mode Z5

Inactive

1342


N/A

1343

X(Z5)+, Reactance for Forward direction

N/A

1344


N/A

1345

T5 delay

N/A

1346

X(Z5)-, Reactance for Reverse direction

N/A

4.13 Group Power Swing

20 of 25

No.

Settings

Value

2002

Power Swing Operating mode

Z2 to Z5 Block

2006

Power swing trip

YES

2007

Trip delay after Power Swing Blocking

0.08 sec

4.14 Group Teleprotection for Distance prot. No.

Settings

Value

2101

Teleprotection for Distance protection

PUTT(Z1B)

2102

Type of Line

Two Terminals

2103A

Time for send signal prolongation

0.07 sec

2109A

Transient Block.: Duration external flt.

oo sec

2110A

Transient Block.: Blk.T. after ext. flt.

0.05 sec

4.15 Group Instantaneous HighSpeed SOTF Overcurrent No.

Settings

Value

2401

Inst. High Speed SOTF-O/C is

ON

2404

I>>> Pickup

2.5 A

4.16 Group Measurement Supervision; Group Balance / Summ. No.

Settings

Value

2901

Measurement Supervision

ON

2902A

Voltage Threshold for Balance Monitoring

10

2903A

Balance Factor for Voltage Monitor

0.8

2904A

Current Balance Monitor

0.1

2905A

Balance Factor for Current Monitor

0.05

2906A

Summated Current Monitoring Threshold

0.10 A

2907A

Summated Current Monitoring Factor

0.1

2908A

T Balance Factor for Voltage Monitor

5 sec

2909A

T Current Balance Monitor

5 sec

4.17 Group Measurement Supervision; Group Fuse Fail. Mon. No.

Settings

Value

21 of 25

2910

Fuse Failure Monitor

ON

2911A

Minimum Voltage Threshold U>

50 V

2912A

Maximum Current Threshold I<

0.20 A

2913A

Maximum Voltage Threshold U< (3phase)

5V

2914A

Delta Current Threshold (3phase)

0.10 A

2915

Voltage Failure Supervision

with current supervision

2916A

Delay Voltage Failure Supervision

3.00 sec

4.18 Group Measurement Supervision; Group VT mcb No.

Settings

Value

2921

VT mcb operating time

0 ms

4.19 Group Measurement Supervision; Group Load Angle No.

Settings

Value

2941

Limit setting PhiA

200 °

2942

Limit setting PhiB

340 °

2943

Minimum value I1>

0.05 A

2944

Minimum value U1>

20 V

4.20 Group Earth fault overcurrent; Group General No.

Settings

Value

3101

Earth Fault overcurrent function

ON

3102

Block E/F for Distance protection

with every Pickup

3174

Block E/F for Distance Protection Pickup

in each zone

3103

Block E/F for 1pole Dead time

YES

3104A

Stabilisation Slope with Iphase

10%

3109

Single pole trip with earth flt.prot.

YES

3170

2nd harmonic ratio for inrush restraint

15%

3171

Max.Current, overriding inrush restraint

7.50 A

3172

Instantaneous mode after SwitchOnToFault

with Pickup and direction

3173

Trip time delay after SOTF

0.00 sec

22 of 25

4.21 Group Earth fault overcurrent; Group 3I0>>> No.

Settings

Value

3110

Operating mode

Inactive

3111

3I0>>> Pickup

N/A

3112

T 3I0>>> Time delay

N/A

3113

Instantaneous trip via Teleprot./BI

N/A

3114


N/A

3115

Inrush Blocking

N/A

4.22 Group Earth fault overcurrent; Group 3I0>> No.

Settings

Value

3120

Operating mode

Inactive

3121

3I0>> Pickup

N/A

3122

T 3I0>> Time Delay

N/A

3123


N/A

3124


N/A

3125

Inrush Blocking

N/A

4.23 Group Earth fault overcurrent; Group 3I0> No.

Settings

Value

3130

Operating mode

Inactive

3131

3I0> Pickup

N/A

3132

T 3I0> Time Delay

N/A

3133


N/A

3134


N/A

3135

Inrush Blocking

N/A

4.24 Group Earth fault overcurrent; Group 3I0 InverseTime No.

Settings

Value

3140

Operating mode

Forward

3141

3I0p Pickup

0.10 A

23 of 25

3143

3I0p Time Dial

0.34 sec

3147

Additional Time Delay

0.00 sec

3148


YES

3149


NO

3150

Inrush Blocking

YES

3151

IEC Curve

Normal Inverse

4.25 Group Earth fault overcurrent; Group Direction No.

Settings

Value

3160

Polarization

with U0 + IY (dual polarized)

3162A

ALPHA, lower angle for forward direction

338 °

3163A

BETA, upper angle for forward direction

122 °

3164

Min. zero seq.voltage 3U0 for polarizing

N/A

3166

Min. neg. seq. polarizing voltage 3U2

5.0 V

3167

Min. neg. seq. polarizing current 3I2

0.50 A

3168

Compensation angle PHI comp. for Sr

255 °

3169

Forward direction power threshold

0.3 VA

4.26 Group Automatic Reclosure; Group General No.

Settings

Value

3401

Auto-Reclose function

ON

3402

CB ready interrogation at 1st trip

NO

3403

Reclaim time after successful AR cycle

3.00 sec

3404

AR blocking duration after manual close

1.00 sec

3406

Evolving fault recognition

with Trip

3407

Evolving fault (during the dead time)

starts 3pole AR-cycle

3408

AR start-signal monitoring time

0.20 sec

3409

Circuit Breaker (CB) Supervision Time

3.00 sec

3410

Send delay for remote close command

∞sec

3411A

Maximum dead time extension

∞sec

24 of 25

4.27 Group Automatic Reclosure; Group 1st AR-cyle No.

Settings

Value

3450

Start of AR allowed in this cycle

YES

3451

Action time

0.20 sec

3456

Dead time after 1pole trip

1.20 sec

3457

Dead time after 3pole trip

0.50 sec

3458

Dead time after evolving fault

1.20 sec

3459

CB ready interrogation before reclosing

NO

3460

Request for synchro-check after 3pole AR

NO

4.28 Group Automatic Reclosure; Group 3pTRIP/DLC/RDT No.

Settings

Value

3430

3pole TRIP by AR

YES

3431

Dead Line Check or Reduced Dead Time

Without

3438

Supervision time for dead/ live voltage

0.10 sec

3440

Voltage threshold for live line or bus

48 V

3441

Voltage threshold for dead line or bus

30 V

4.29 Group Automatic Reclosure; Group Start AR with.. No.

Settings

Value

3420

AR with distance protection

YES

3421

AR with switch-onto-fault overcurrent

NO

3423

AR with earth fault overcurrent prot.

NO

4.30 Group Voltage Protection; Group U> Phase-Earth No.

Settings

Value

3701

Operating mode Uph-e overvoltage prot.

ON

3702

Uph-e> Pickup

69.9 V

3703

T Uph-e> Time Delay

5.00 sec

3704

Uph-e>> Pickup

95.3 V

3705

T Uph-e>> Time Delay

0.10 sec

25 of 25

3709A

Uph-e>(>) Reset ratio

0.95

4.31 Group Fault Locator No.

Settings

Value

3802

Start fault locator with

Pickup

3806

Load Compensation

YES

26 of 25

400/220kV WARANGAL SUBSTATION

SIEMENS

400/220 KV WARANGAL SUBSTATION 220kV DURSHED FEEDER ABB DISTANCE PROTECTION RELAY SETTING CALCULATION Type : ABB make REL670 System Particulars

HOLD

A

Line Parameters

1

Rated line voltage

2

Line Length

3

Max power flow in the line (assumed)

4

Postive sequence resistance

0.0791 ohms/km

5

Postive sequence reactance

0.403 ohms/km

6

Zero sequence resistance

0.255 ohms/km

7

Zero sequence reactance

1.51 ohms/km

8

Zero sequence mutual resistance (MR)

220 KV 71 KM 150 MVA

0 ohms/km

(If Parallel line in service Mutual Impedance is 60% of zero seq.) 9

Zero sequence mutual reactance (MX)

B

Adjoining line parameters

B.1

Adjacent Line(Short Line)

0 ohms/km

1

Length of adjacent line

2


0.079 ohms/km

3


0.403 ohms/km

4


0.255 ohms/km

5


1.51 ohms/km

B.2

71 KM

longest line

1

Length of longest line

50 KM

2


0.079 ohms/km

3


0.403 ohms/km

4


0.255 ohms/km

5


1.51 ohms/km

45 OF 205


SIEMENS

B.3

Transformer

1

Transformer impedance in p.u

0.125

2

Transformer rating

C

Source impedance

1

Local End max. Fault MVA =1.732*220*40

2

Local End min. Fault MVA =30 % of 15241.6

4572 MVA

3

Local End Z magnitude = (220 x 220) / 15241.6

3.176 ohms

4

Local End Z argument

5

Remote End Max. Fault MVA (Assumed -Not available)

7500 MVA

6

Remote End Min. Fault MVA (Assumed -Not available)

3000 MVA

7

Remote End Z magnitude = (220 x 220) / 7500

6.45 ohms

8

Remote End Z argument

9

Postive sequence resistance at local end = line length x + ve seq. R

100 MVA

15241.6 MVA

84 deg.

84 deg.

46 OF 205

5.616 ohms


SIEMENS

10

Postive sequence reactance at local end = line length x +ve seq.X

28.613 ohms

11

Postive sequence resistance at remote end = line length x +ve seq. R

5.6161 ohms

12

Postive sequence reactance at remote end = line length x +ve seq. X

28.613 ohms

D

CT and PT Detail

1

CT primary rating

2

CT secondary rating

3

PT primary rating

4

PT secondary rating

E

Relay Detail

1

Rated current

1A

2

Rated voltage

110 V

F

System Parameters

1

Arc Resistance + Tower footing resistance - Rfn

50.000 ohms

2

Rf for phase to phase fault

10.000

3

Imp Ratio = CTR / PTR

0.400

4

% for zone-1 setting

0.800

5

% of the adjoining line for Zone2

0.500

6

% of the adjoining line for Zone 3

1.100

G

Protected Line Impedance in CT secondary

1

Postive sequence resistance = line length x + ve seq. R x Imp Ratio =

2.246 ohms

2

Postive sequence reactance = line length x + ve seq. X x Imp Ratio =

11.445 ohms

3

Zero sequence resistance = line length x Z0 x Imp Ratio =

7.242 ohms

4

Zero sequence reactance = line length x Z0X x Imp Ratio =

42.884 ohms

5

Zero sequence mutual resistance = line length x MR x Imp Ratio =

0.000 ohms

6

Zero sequence mutual reactance = line length x MX x Imp Ratio =

0.000 ohms

H

Adjacent Line Impedance in CT secondary

1


2.244 ohms

2


11.445 ohms

3


7.242 ohms

4


42.884 ohms

I

Longest Line Impedance in CT secondary

1


800 A 1A 220000 V 110 V

47 OF 205

1.580 ohms


SIEMENS

2


8.060 ohms

3


5.100 ohms

4


30.200 ohms

J

Zone I : Reach Setting Proposed at 80% of the protected Line

1

Reach For Postive sequence resistance (80% line length x Postive sequence resistance x Imp Ratio =0.8 x 71 x 0.0791 x 0.4

2

1.797 ohms

Reach For Postive sequence reactance (80% line length x Postive sequence reactance x Imp Ratio =0.8 x 71 x 0.403 x 0.4

3

9.156 ohms

Reach For Zero sequence resistance (80% line length x Zero sequence resistance x Imp Ratio =0.8 x 71 x 0.255 x 0.4

4

5.794 ohms

Reach For Zero sequence reactance (80% line length x Zero sequence reactance x Imp Ratio =0.8 x 71 x 1.51 x 0.4

5

6

34.307 ohms

Fault Resistance - ph-e = 1.797 + ( 9.156 x TAN ( 25 ) =

6.067

= 4.5 x 1.797 =

8.0865

= 50 x 0.4 =

20.000

Maximum of 6.067 and 20 =

20.000

Minimum of 8.0865 and 20 =

8.087 ohms

Hence fault resistance between phase to earth =

8.087 ohms

Fault Resistance - ph-ph = 1.797 + ( 9.156 x TAN ( 25 ) =

6.067

= 3 x 1.797 =

5.391

= 10 x 0.4 =

4.000

48 OF 205


SIEMENS

Maximum of 6.067 and 4 =

6.067

Minimum of 5.391 and 6.067 =

5.391

Hence fault resistance between phase to phase =2 times of the above

K

10.782 ohms

Zone II: Reach Setting at (100% of the protected Line + 50% of the shortest line at Next substation)

1

Reach For Postive sequence resistance 100% line length x Postive sequence resistance x Imp Ratio + 50% shortest line length x Postive sequence resistance x Imp Ratio =71 x 0.0791 x 0.4 + 0.5 x 71 x 0.0791 x 0.4

2

3.368 ohms

Reach For Postive sequence reactance 100% line length x Postive sequence reactance x Imp Ratio + 50% shortest line length x Postive sequence reactance x Imp Ratio =71 x 0.403 x 0.4 + 0.5 x 71 x 0.403 x 0.4

3

17.168 ohms

Reach For Zero sequence resistance 100% line length x Zero sequence resistance

x Imp Ratio +

50% shortest line length x Zero sequence resistance

x Imp Ratio

=71 x 0.255 x 0.4 + 0.5 x 71 x 0.255 x 0.4

4

10.863 ohms

Reach For Zero sequence reactance 100% line length x Zero sequence reactance

x Imp Ratio +

50% shortest line length x Zero sequence reactance

x Imp Ratio

=71 x 1.51 x 0.4 + 0.5 x 71 x 1.51 x 0.4

64.326 ohms

5

Fault Resistance - ph-e

15.156 ohms

6

Fault Resistance - ph-ph

20.208 ohms

L

Zone III: Reach Setting Proposed at 110% of the prot Line & 100%of the longest line

1

Reach For Postive sequence resistance

49 OF 205


SIEMENS

110% line length x Postive sequence resistance x Imp Ratio + 100% Longest line length x Postive sequence resistance x Imp Ratio = 1.1 x 71 x 0.0791 x 0.4 + 50 x 0.0791 x 0.4

2

4.053 ohms

Reach For Postive sequence reactance 110% line length x Postive sequence reactance x Imp Ratio + 100% Longest line length x Postive sequence reactance x Imp Ratio = 1.1 x 71 x 0.403 x 0.4 + 50 x 0.403 x 0.4

3

20.650 ohms

Reach For Zero sequence resistance 110% line length x Zero sequence resistance x Imp Ratio + 100% Longest line length x Zero sequence resistance

x Imp Ratio

= 1.1 x 71 x 0.255 x 0.4 + 50 x 0.255 x 0.4

3

13.066 ohms

Reach For Zero sequence reactance 110% line length x Zero sequence reactance x Imp Ratio + 100% Longest line length x Zero sequence reactance x Imp Ratio = 1.1 x 71 x 1.51 x 0.4 + 50 x 1.51 x 0.4

77.372 ohms

5

Fault Resistance - ph-e

18.239 ohms

6

Fault Resistance - ph-ph

24.319 ohms

M

Power Swing Block Function

1

Reactive direction are set so that the inner characteristic covers completely all the distance protection zones,which are to be blocked by the PSD function.At least 10%of additional safely margin

2

Reactive Reach of the Inner characteristic of the Power swing blocking element = 1.1* X3

22.715

3

Reactive Reach of the Inner characteristic of the Power swing blocking element = 1.1(2R3+Rf)

28.980

4

Reactive Reach of the Outer characteristic of the Power swing blocking element

28.393

5

Reactive Reach of the Outer characteristic of the Power swing blocking element

36.224

50 OF 205


SIEMENS

N

Source Impedance refered to CT secondary

1

Local End Z magnitude

1.270

2

Local End Z argument

80.000

3

Remote End Z magnitude

2.580

4

Remote End Z argument

80.000

5

Postive sequence resistance at local end in ohms(RISA)

2.246

6

Postive sequence reactance at local end in ohms(XISA)

11.445

7

Postive sequence resistance at remote end in ohms(R1SB)

2.246

8

Postive sequence reactance at remote end in ohms(X1SB)

11.445

O

Phase Selection

1

X1Phs

41.299

2

X0Phs

154.745

3

Calculated RFPEphs

50.593

4

Calculated RFPPphs

44.584

5

Zloadmin =(KV)2\MVA

6

RFPEphs

50.593

7

Conditions for 2nd Zone

29.360

8

Conditions for 4th Zone

4.180

9

Conditions for 3-ph fault

51.979

10

RFPPphs

44.584

104.544

9.451

51 OF 205

13.985

SIEMENS


400/220 KV WARANGAL SUBSTATION 220kV DURSHED FEEDER ABB DISTANCE PROTECTION RELAY SETTING Type : ABB make REL670 DESCRIPTION Max. load current \ CT primary current

Distance Protection zone 1

PARAMETER SETTING lb (FLC \ CT Primary)

0.492

lminop

0.200

HOLD

operating mode and directionaity of zone I

RECOMMENDED

operation

Forward

Settings of Phase to Phase measurement Operation of distance protection zone I for Ph-I

Operation PP

On

Positive sequence reactance of zone 1 for ph-ph fault

X1PP

9.156


R1PP

1.797

Resisitive reach of distance protection for ph-ph faults

RFPP

10.782

Operating mode of time delayed trip for the distance protection zone 1 for ph-ph faults

Timer t1PP

Time delayed trip operation for the distance protection zone 1 for ph-ph faults

t1PP

On 0.000

Settings of Phase to earth element Operation of distance protection zone I for Ph-I

Operation PE

On

X1PE

9.156

R1PE

1.797

Zero sequence line reactance included in distance protection zone I XOPE for Ph-E faults

34.307

Zero sequence line reactance included in distance protection zone I ROPE for Ph-E faults

5.794

Resisitive reach for zone 1 Ph-E faults

RFPE

8.087

Operating mode of time delayed trip for the distance protection zone 1 for ph-E faults

Timer t1PP

Positive sequence resistive reach of distance zone 1 for ph-E fault

48 OF 205

On

SIEMENS



t1PE

49 OF 205

0.000

SIEMENS


Distance Protection zone II

ZONE II

operating mode and directionaity of distance zone II

operation

Forward

Settings of Phase to Phase measurement Operation of distance protection zone 2 for Ph-Ph fault

Operation PP

On


X1PP

17.168


R1PP

3.368

Resisitive reach of distance protection for ph-ph faults

RFPP

20.208

Operating mode of time delayed trip for the distance protection zone 2 for ph-ph faults

Timer t1PP


t1PP

On 0.400

Settings of Phase to earth element Operation of distance protection zone 2 for Ph-E faults

Operation PE

On

X1PE

17.168

R1PE

3.368

Zero sequence line reactance included in distance protection zone XOPE 2 for Ph-E faults

64.326

Zero sequence line reactance included in distance protection zone ROPE 2 for Ph-E faults

10.863

Resisitive reach for zone 2 Ph-E faults

RFPE

15.156

Operating mode of time delayed trip for the distance protection zone 2 for ph-E faults

Timer t1PP


t1PE

Distance protection zone lll

ZONEIII

Operating mode and directionality of zone 3

Operation

Positive sequence resistive reach of distance zone 2 for ph-E fault

On 0.400

Forward

SETTINGS OF PHASE TO PHASE MEASUREMENT Operation of Distance protection Zone 3 for Ph fault

Operation PP

Positive sequence reactance of zone 3 for phase to phase faults

X1PP

20.650

Positive sequence resistance of zone 3 for phase to phase faults

R1PP

4.053

Positive reach of distance protectin for phase to phase faults

RFPP

24.319

50 OF 205

On

SIEMENS


Operating mode of time delayed trip for the distance protection zone 3 for Ph-Ph faults

Timer t3PP

On

Time delaye trip operation for the distnce protection zone 3 for Pht3PP Ph faults

1.000

SETTINGS OF PHASE TO EARTH MEASUREMENT Operating mode of distance protection zone 3 for Ph-E faults

Operation PE

On

Positive sequence reactive reach of distance zone 3 for Ph-E faults X1PE

20.650

Positive sequence resistive reach of distance zone 3 for Ph-E faults R1PE

4.053

zero sequence line reactance included in distance protection zone 3 X0PE for Ph-E faults Zero sequence line reactance included in distance protection zone R0PE 3 for Ph-E faults Resistive reach for zone 3 for Ph-E faults

77.372 10.863

RFPE

Operating mode of time delayed trip for the distance protection zone 3 for Ph-E faults Time delayed trip operation of the distance protection zone 3 for Ph-E faults Manual energising time

18.239

Timer t3PE

On

t3PE

1.000

T manenerg

0.200

PHASE SELECTION operation of phase selection

operation

positive sequence reactive reach for ph-ph loop measurement

X1PP

20.650

Resistive reach for ph-ph loop measurement

RFPP

24.319

positive sequence reactive reach for ph-e loop measurement

X1PE

20.650

Zero sequence reactive for ph-e loop measurement

XOPE

77.372

Resistive reach for ph-e loop measurement

RFPE

18.239

Power swing blocking

On

PSB

power swing function on/off

operation

On

Operating mode of internal PSD function

detection

on

positive sequence reactive reach of the inner boundary

X1IN

22.715

positive sequence reactive reach of the inner boundary

R1IN

28.980

reach multiplication for the outer reactive boundary

KX

1.250

reach multiplication for the outer reactive boundary

KR

1.250

Initial PSD timer

tp1

0.045

Fast PSD timer

tp2

0.015

51 OF 205

SIEMENS


Hold timer for activation of fast PSD timer

tw

0.250

Hold timer for PSD detected

th

0.5s

Timer over coming 1-phase reclosing dead time

tEF

3s

Timer to time delay block by the residual current

tR1

0.300

On delay timer for blocking of output signal at very slow swings

tR2

2.000

Scheme communication logic

Zcom

Operation of zoom scheme communication logic

Operation

Operation mode

Schemetype

Coordination timer

T coord

Minimum duration of a carrier send signal

T sendmin

0.1s

Operation mode for an unblocking signal

Unblock

Off

Security timer

T security

Operation mode of current reversal function

Currev

Off

Pick up time of current reversal function

T pickup

NA

Time delay for current reversal

T delay

NA

Operation mode of WEI function

WEI

Off

Coordination time for WEI function

Twei

NA

Voltage detection for PH-E faults

UPN<

NA

voltage detection for Ph-Ph faults

UPP<

NA

Automatic SOTF

SOTF

Operation of SOTF

Operation

FUSE FAILURE FUNCTION

FFR

FFR zero sequence function On\Off

Zeroseq

Operating value of voltage U0

3U0>

0.100

Operating value of current I0

3Uo<

0.100

BROKEN CONDUCTOR SUPERISION

SSUP

Broken conductor function On\Off

Operation

Operating phase current as a%

IP>

52 OF 205

On Permissive UR 0.050s

0.035s

On

On

On 0.100

SIEMENS


Time delay

T

0.200

Loss of voltage

YU<

Loss of voltage function On\Off

Operation

Operating phase voltage as a%

UPE<

overload

I>

Overload function On\Off

Operation

operating value of phase current

IP>

Time delay

T

20s

Unit for presentation of line length

Length unit

Km

Length of protected line

Line length

71.000

Positive sequence reactance of line

X1

28.613

Positive sequence resistance of line

R1

5.616

zero sequence reactance of line

X0

107.210

Zero sequence resistance of line

R1

18.105

Positive sequence reactance of source at local end

X1SA

28.613

Positive sequence resistance of source at local end

R1SA

5.616

Positive source reactance at remote end

X1SB

28.613

Positive source resistance at remote end

R1SB

5.616

Zero sequence mutual reactance for double circuit line

XM0

Zero sequence mutual resistance for double circuit line

RM0

Selection of presentation mode for the distance to fault *

Distance unit

Analogue signal name**

Name

Primary phase-phase voltage

VT prim

220.000

Primary rated current

CT prim

800.000

On 0.700

On 1.000

FAULT LOCATOR

NOTES: ALL parameters of fault locator are set in the menu-settings-functions-group n-line.reference *Settings done in menu: settings - Distrbreport-faultlocator **settings done in menu:configuration-analogue inputs-u1,u2 etc

53 OF 205

Km

SIEMENS


SYNCRO CHECK AND ENERGISATION CHECK FUNCTIONS: Operation of syncro check function

Operation

On

Reference voltage either phase to ground or phase to phase

Input phase

L1

Phase shift between U bus & U line

Phase shift

10.000

Voltage ratio between U bus & Uline

U ratio

1.000

Bus arrangment for voltage selection

U selection

single bus

Autoenergisation check

Autoenerg

Off

Mannual energisation check

Manenerg

Off

Mannual energisation check

ManDBDL

Off

High voltage limit

Uhigh

0.800

Low voltage limit

Ulow

0.400

Frequency difference limit

Freqdiff

0.200

Phase angle difference limit

Phasediff

20.000

Voltage difference limit

Udiff

0.200

Autoenergisation check

T autoenerg

0.200

Manual energising time

T manenerg

0.200

54 OF 205

Distance Setting Excel

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